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TABLE OF CONTENTS
PIONEER DRILLING COMPANY INDEX TO CONSOLIDATED FINANCIAL STATEMENTSTable of Contents

As filed with the Securities and Exchange Commission on August 4, 2004February 7, 2005

Registration No. 333-117279333-            

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

Amendment No. 2
to
FORM S-1
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933

PIONEER DRILLING COMPANY
(Exact name of registrant as specified in its charter)

Copies to:

Approximate date of commencement of proposed sale to the public:As soon as practicable after the effective date of this registration statement.

        If any of the securities being registered on this Form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box.    o

        If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, please check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.    o

        If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.    o

        If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.    o

        If delivery of the prospectus is expected to be made pursuant to Rule 434, please check the following box.    o

CALCULATION OF REGISTRATION FEE

(1)

Includes 1,575,000 shares of Common Stock subject to an over-allotment option granted to the Underwriters.

(2)

Estimated in accordance with Rule 457(c) of the Securities Act of 1933, as amended, solely for the purpose of computing the amount of the registration fee, based on the average of the high and low sales prices of the Registrant's Common Stock as reported on the American Stock Exchange on February 1, 2005.

        The Registrant hereby amends this registration statement on such date or dates as may be necessary to delay its effective date until the Registrant shall file a further amendment which specifically states that this registration statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933 or until the registration statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.

SUBJECT TO COMPLETION, DATED AUGUST 4, 2004

The information in this prospectus is not complete and may be changed. A registration statement relating to these securities has been filed with the Securities and Exchange Commission. These securities may not be sold until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities and neither we nor the selling shareholders are soliciting an offer to buy these securities in any jurisdiction where the offer or sale is not permitted.

SUBJECT TO COMPLETION, DATED February 7, 2005

PROSPECTUS

8,582,01810,500,000 Shares

Common Stock

        We are offering 4,000,0005,000,000 shares of our common stock and the selling shareholders identified on page 6059 of this prospectus are offering a total of 4,582,0185,500,000 shares of our common stock. We will not receive any of the proceeds from the shares of our common stock sold by the selling shareholders.

        TheWEDGE Energy Services, L.L.C., one of the selling shareholders, acquired the 5,000,000 shares of common stock offeredit is offering by this prospectus directly from us in private placements. We are registering the offer and sale of thethose shares of common stock to satisfy registration rights we have granted to some of the selling shareholders.WEDGE. See "Selling Shareholders."

        Our common stock trades on The American Stock Exchange under the symbol "PDC." On August 3, 2004,February 4, 2005, the last reported sale price for our common stock was $7.35$10.62 per share.

        Investing in our common stock involves a high degree of risk. See "Risk Factors" beginning on page 7 of this prospectus.

(1)

Chesapeake Energy Corporation ("Chesapeake") has notified us of its intent to exercise its preemptive rights with respect to shares of our common stock that we offer in this offering. The underwriters will repay to us any discounts and commissions they receive that are applicable to the shares offered by us and purchased by Chesapeake in connection with the exercise of its preemptive rights relating to this offering. See "Underwriting—Commission and Expenses."

(2)

Assumes that Chesapeake will exercise its preemptive rights in full with respect to all the shares allocated to it.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

        Delivery of the shares of common stock is expected to be made on or about             , 2004.2005. The underwriters have an option to purchase an additional 600,000787,500 shares from us and an additional 687,302787,500 shares from one of the selling shareholders, WEDGE Energy Services, L.L.C., to cover over-allotments of shares.

The date of this prospectusProspectus is                          , 2004

2005.

TABLE OF CONTENTSTable of Contents

        You should rely only on the information in this prospectus. We have not, and the selling shareholders and the underwriters have not, authorized anyone to provide you with information that is different. This document may only be used where it is legal to sell these securities.

i

PROSPECTUS SUMMARY

        This summary highlights selected information described more fully elsewhere in this prospectus. This summary may not contain all the information that is important to you. You should read the entire prospectus, including the risks of investing in our common stock discussed in the "Risk Factors" section and our consolidated financial statements and related notes, before making an investment decision with respect to this common stock offering. References in this prospectus to "we", "our", "us","we," "our," "us," "Pioneer" or similar terms mean Pioneer Drilling Company and its subsidiaries, unless the context indicates otherwise.

Our Business

        We provide contract land drilling services to independent and major oil and gas exploration and production companies. In addition to our drilling rigs, we provide the drilling crews and most of the ancillary equipment needed to operate our drilling rigs.

        We conduct our operations primarily in South, East and North Texas.Texas, Western Oklahoma and the Rocky Mountains. During our fiscal year ended March 31, 2004 and through the firstthird quarter of fiscal 2005, substantially all the wells we drilled for our customers were drilled in search of natural gas. Although we have recently diversified our operations somewhat with the November 2004 acquisition of seven drilling rigs from Wolverine Drilling, Inc., with five of those rigs employed in search of oil in the Williston Basin of the Rocky Mountains, our customers remain primarily focused on drilling for natural gas. Natural gas reserves are typically found in deep geological formations and generally require premium equipment and experienced crews to increase drilling success. In addition, the regions in which we operate are natural gas rich areas. Our rig fleet is capable of achieving the depths required to develop the natural gas reserves and our crews have significant operating experience in these regions.

        Over the past five years,Since September 1999, we have significantly expanded our fleet of drilling rigs from six to a current fleet of 3649 drilling rigs through acquisitions, construction of new rigs and the refurbishment of older rigs we owned or acquired. Currently,As of January 31, 2005, we havehad 15 rigs operating in South Texas, 17 rigs operating in East Texas, and four rigs operating in North Texas.Texas, five rigs operating in Western Oklahoma and eight rigs operating in the Rocky Mountains. We own all the rigs in our fleet. The following table summarizes information relating to acquisitions in which we acquired rigs and related operations during the past five years:since September 1999:

(1)

The August 2000 acquisition of Pioneer Drilling Co. involved our acquisition of all the outstanding capital stock of that entity. Each other acquisition reflected in this table involved our acquisition of assets from the indicated entity.

During that same five-year period, we also added seveneight rigs to our fleet through construction of new rigs and construction of rigs from new and used components. In addition, in August 2003, we aquiredacquired a rig that had been operating in Trinidad and integrated it into our operations in Texas. As of JulyJanuary 31, 2004,2005, we owned a fleet of 5359 trucks and related transportation equipment used to transport our drilling rigs to and from drilling sites. By owning our own trucks, we reduce the cost of rig moves and the downtime between rig moves.

        We obtain our contracts for drilling oil and gas wells either through competitive bidding or through direct negotiations with customers. Our drilling contracts generally provide for compensation on either a daywork, turnkey or footage basis. Contract terms we offer generally depend on the complexity and risk of operations, the on-site drilling conditions, the type of equipment used and the anticipated duration of the work to be performed. Under daywork drilling contracts, we provide a drilling rig with required personnel to our customer who supervises the drilling of the well. We are paid based on a

negotiated fixed rate per day while the rig is used. Under a turnkey contract, we agree to drill a well for our customer to a specified depth and under specified conditions for a fixed price, regardless of the time required or the problems encountered in drilling the well. Under footage contracts, we are paid a fixed amount for each foot drilled, regardless of the time required or the problems encountered in drilling the well. We typically pay more of the out-of-pocket costs associated with footage contracts compared with daywork contracts. The following table presents, by type of contract, information about the total number of wells we completed for our customers during the nine months ended December 31, 2004 and each of the last three fiscal years.

Our Strategy

        Our goal is to continue to build on our strong market position and reputation as a quality contract drilling company in a way that enhances shareholder value. We intend to accomplish this goal by:

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continuing to own and operate a high-quality fleet of land drilling rigs, primarily in active natural gas drilling markets;



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fueling growth through the acquisition ofacquiring high-quality rigs capable of drilling for natural gas reserves and capable of generating our targeted returns on investment;



•

positioning ourselves to maximize rig utilization and dayrates;



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training and maintaining high quality,high-quality, experienced crews capable of employing drilling techniques that are best suited to the regional subsurface geology;crews; and



•

maintaining the recent improvements in our safety record.

Our Industry

        We operate in the United States contract land drilling services industry, providing products and services to oil and natural gas exploration and production companies engaged in the drilling for and production of oil and natural gas. Demand for our products and services depends primarily on our customers' willingness to spend capital on the exploration and development of natural gas.activities. Our customers' capital spending decisions are driven by their perspectives on current and future oil and natural gas prices, their access to capital and available exploration and development opportunities.

        We believe capital spent on incremental natural gas production will be driven by an increase in hydrocarbon demand as well as shortages in supply of natural gas. The Energy Information Agency recently estimated that U.S. consumption of natural gas exceeded U.S. domestic productive capacity by 20%15% in 20022003 and forecasts that U.S. consumption of natural gas will exceed U.S. domestic productive capacity by 28%25% by 2010. Most of this difference is expected to be driven by the growth in consumption by electric power generators, as a significant amount of natural gas-fired power generation capacity has been constructed within the last five years and older, less-efficient power generation capacity, not fired by natural gas, is expected to be decommissioned. In addition, a study published by the National Petroleum Council in September 2003 concluded from drilling and production data over the preceding 10 years that average "initial production rates from new wells have been sustained through the use of advanced technology; however, production declines from these initial rates have increased significantly;

and recoverable volumes from new wells drilled in mature producing basins have declined over time. Without the benefit of new drilling, indigenous supplies have reached a point at which U.S. production declines by 25% to 30% each year. Eighty percent of gas production in 10 years will be from wells yet to be drilled." We believe all of these factors tend to support a higher natural gas price environment, which should create strong incentives for oil and natural gas exploration and production companies to increase drilling activity in North America. Consequently, these factors may result in higher rig dayrates and rig utilization.

Recent Developments

        Private Placement of Common Stock.New Credit Facility.    On February 20,October 29, 2004, we sold 4,400,000 sharesentered into a $47 million credit facility with a group of our common stock at $5.40 per share inlenders. The new credit facility provides us with a private placement to various individuals$7 million revolving line and institutional investors, allletter of whom were accredited investors,credit facility and a $40 million acquisition facility for $23.8 million in proceeds, before related offering expenses. We subsequently filed a registration statement to register resales of those shares, and that registration statement became effective on June 22, 2004. We used $12 million of the proceeds to complete the acquisition of drilling rigs, rig transportation equipment and associated equipment. Borrowings under the new credit facility bear interest at a rate equal to Frost National Bank's prime rate (5.25% at January 31, 2005) and are secured by most of our assets, from Sawyer Drilling & Service, Inc.including all our drilling rigs, associated equipment and the remainder to purchase additional drilling equipment, trucking assets and for general corporate purposes.receivables.

        SawyerWolverine Drilling Asset Acquisition.    On March 4,November 30, 2004, we completed the acquisition of theseven drilling assets of Sawyerrigs and related equipment from Wolverine Drilling, & Service, Inc., based in Shreveport, Louisiana.Kenmare, North Dakota. We paid $12$28 million for a seven-rig drillingthe fleet and related yard equipment. The fleet consists of seven 700mechanical 500 to 1,2001,000 horsepower mechanicaldrilling rigs, capable of drilling to depths of 8,0007,000 to 14,000 feet. These15,000 feet, and related assets, including a 4.7-acre rig storage and maintenance yard in Kenmore, North Dakota and noncompetition agreements with the two stockholders of Wolverine Drilling.

        Allen Drilling Asset Acquisition.    On December 15, 2004, we completed the acquisition of five drilling rigs are currentlyand related equipment from Allen Drilling, based in serviceWoodward, Oklahoma. We paid $7.2 million for the fleet of five mechanical 550 to 800 horsepower drilling rigs, capable of drilling to depths of 6,000 to 11,000 feet, and a 17-acre rig storage and maintenance yard located in East Texas.Woodward, Oklahoma. We also entered into a noncompetition agreement with Mr. Dixon Allen, President of Allen Drilling.

        Our principal executive offices are located at 9310 Broadway, Bldg. I, San Antonio, Texas 78217 and our phone number at that address is (210) 828-7689. Our website can be found at www.pioneerdrlg.com. Information contained in our website is not incorporated by reference into this prospectus and you should not consider information contained in our website as part of this prospectus.

The Offering

(1)

The numbersnumber of shares of our common stock outstanding after the offering set forth above is based on 27,305,12638,914,978 shares of common stock outstanding as of JulyJanuary 31, 20042005 and includes (i) the shares to be sold by us in this offering, excluding 600,000787,500 shares that we may sell upon exercise of the underwriters' over-allotment option, and (ii) the 6,496,519 shares of common stock issuable upon conversion of the $28 million in aggregate principal amount of our 6.75% convertible subordinated debentures due July 3, 2007, which the holders have agreed to convert immediately prior to the closing of this offering.option. The number of shares outstanding after the offering does not include an aggregate of 4,458,0793,944,746 shares of common stock reserved for issuance under our equity compensation plans, of which 2,086,6662,028,333 shares were subject to outstanding stock options as of JulyJanuary 31, 20042005, at a weighted average exercise price of $3.29$4.85 per share.

Summary Financial Data

        The following table sets forth our summary historical financial data as of and for each of the fiscal years and interim periods indicated and is derived from our historical audited consolidated financial statements for the fiscal years indicated and from our historical unaudited consolidated financial statements for the interim periods indicated. You should review this information together with "Management's Discussion and Analysis of Financial Condition and Results of Operations" beginning on page 2120 of this prospectus and the consolidatedour historical financial statements and related notes included in this prospectus contains.prospectus.

RISK FACTORS

        Investment in our common stock involves a high degree of risk. You should carefully consider the following risk factors as well as other information in this prospectus before making your investment decision. The risks described below are not the only risks we face. Additional risks that we do not yet know of or that we currently think are immaterial may also impair our business operations. If any of the events or circumstances described below actually occurs, our business, financial condition or results of operations could be materially adversely affected. In such case, the trading price of our common stock could decline, and you may lose all or part of your investment.

Risks Relating to the Oil and Gas Industry

We derive all our revenues from companies in the oil and gas exploration and production industry, a historically cyclical industry with levels of activity that are significantly affected by the levels and volatility of oil and gas prices.

        As a provider of contract land drilling services, our business depends on the level of drilling activity by oil and gas exploration and production companies operating in the geographic markets where we operate. The oil and gas exploration and production industry is a historically cyclical industry characterized by significant changes in the levels of exploration and development activities. Oil and gas prices, and market expectations of potential changes in those prices, significantly affect the levels of those activities. Worldwide political, economic and military events have contributed to oil and gas price volatility and are likely to continue to do so in the future. Any prolonged reduction in the overall level of exploration and development activities, whether resulting from changes in oil and gas prices or otherwise, can materially and adversely affect us in many ways by negatively impacting:

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our revenues, cash flows and profitability;



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the fair market value of our rig fleet;



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our ability to maintain or increase our borrowing capacity;



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our ability to obtain additional capital to finance our business and make acquisitions, and the cost of that capital; and



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our ability to retain skilled rig personnel whom we would need in the event of an upturn in the demand for our services.

        Depending on the market prices of oil and gas, oil and gas exploration and production companies may cancel or curtail their drilling programs, thereby reducing demand for our services. Oil and gas prices have been volatile historically and, we believe, will continue to be so in the future. Many factors beyond our control affect oil and gas prices, including:

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weather conditions in the United States and elsewhere;



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economic conditions in the United States and elsewhere;



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actions by OPEC, the Organization of Petroleum Exporting Countries;



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political instability in the Middle East and other major oil and gas producing regions;



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governmental regulations, both domestic and foreign;



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domestic and foreign tax policy;



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the pace adopted by foreign governments for the exploration, development and production of their national reserves;



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the price of foreign imports of oil and gas;

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the cost of exploring for, producing and delivering oil and gas;



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the discovery rate of new oil and gas reserves;



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the rate of decline of existing and new oil and gas reserves;



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available pipeline and other oil and gas transportation capacity;



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the ability of oil and gas companies to raise capital; and



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the overall supply and demand for oil and gas.

Risks Relating to Our Business

We have a history of losses and may experience losses in the future.

        We have a history of losses. We incurred net losses of $1.8 million, $5.1 million and $0.4 million in the fiscal years ended March 31, 2004, 2003 and 2000, respectively. Our profitability in the future will depend on many factors, but largely on utilization rates and dayrates for our drilling rigs. Our current utilization rates and dayrates may decline and we may experience losses in the future.

Our acquisition strategy exposes us to various risks, including those relating to difficulties in identifying suitable acquisition opportunities and integrating businesses, assets and personnel, as well as difficulties in obtaining financing for targeted acquisitions and the potential for increased leverage or debt service requirements and our ability to identify suitable acquisition opportunities.requirements.

        As a key component of our business strategy, we have pursued and intend to continue to pursue acquisitions of complementary assets and businesses. Certain risks are inherent in anFor example, since March 31, 2003, our rig fleet increased from 24 to 49 drilling rigs, primarily as a result of acquisitions. We may be unable to continue to identify additional suitable acquisition strategy, such as increasing leverage and debt service requirements and combining disparate company cultures and facilities, which could adversely affect our operating results. Theopportunities, negotiate acceptable terms or successfully acquire identified targets. In addition, the success of any completed acquisition will depend in part on our ability to integrate effectively the acquired business into our operations. The process of integrating an acquired business may involve unforeseen difficulties and may require a disproportionate amount of management attention and financial and other resources. Possible future acquisitions may be for purchase prices significantly higher than those we paid for recent acquisitions. Consequently, we may increase leverage beyond our historical levels to finance those acquisitions. We may be unable to continue to identify additional suitable acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on satisfactory terms or successfully acquire identified targets. Our failure to achieve consolidation savings, to incorporate the acquired businesses and assets into our existing operations successfully or to minimize any unforeseen operational difficulties could have a material adverse effect on our financial condition and results of operations.

        In addition, we may not have sufficient capital resources to complete additional acquisitions. Historically, we have funded the growth of our rig fleet through a combination of debt and equity financing. We may incur substantial additional indebtedness to finance future acquisitions and also may issue equity securities or convertible securities in connection with such acquisitions. Debt service requirements could represent a significant burden on our results of operations and financial condition and the issuance of additional equity could be dilutive to our existing stockholders. Furthermore, we may not be able to obtain additional financing on satisfactory terms.

We operate in a highly competitive, fragmented industry in which price competition is intense.

        We encounter substantial competition from other drilling contractors. Our primary market areas of South, East and North Texas are highly fragmented and competitive. The fact that drilling rigs are mobile and can be moved from one market to another in response to market conditions heightens the competition in the industry.

        The drilling contracts we compete for are usually awarded on the basis of competitive bids. We believe pricing and rig availability are the primary factors our potential customers consider in

determining which drilling contractor to select. In addition, we believe the following factors are also important:

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the type and condition of each of the competing drilling rigs;



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the mobility and efficiency of the rigs;

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the quality of service and experience of the rig crews;



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the safety records of the rigs;



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the offering of ancillary services; and



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the ability to provide drilling equipment adaptable to, and personnel familiar with, new technologies and drilling techniques.

        While we must be competitive in our pricing, our competitive strategy generally emphasizes the quality of our equipment, the safety record of our rigs and the quality of service and experience of our rig crews to differentiate us from our competitors. This strategy is less effective as lower demand for drilling services intensifies price competition and makes it more difficult for us to compete on the basis of factors other than price. In all of the markets in which we compete, an over-supply of rigs can cause greater price competition.

        Contract drilling companies compete primarily on a regional basis, and the intensity of competition may vary significantly from region to region at any particular time. If demand for drilling services improves in a region where we operate, our competitors might respond by moving in suitable rigs from other regions. An influx of rigs from other regions could rapidly intensify competition and reduce profitability and make any improvement in demand for drilling rigs short-lived.

We face competition from many competitors with greater resources which may harm our ability to compete.

        Many of our competitors have greater financial, technical and other resources than we do. Their greater capabilities in these areas may enable them to:

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better withstand industry downturns;



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compete more effectively on the basis of price and technology;



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retain skilled rig personnel; and



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build new rigs or acquire and refurbish existing rigs so as to be able to place rigs into service more quickly than us in periods of high drilling demand.

Unexpected cost overruns on our turnkey drilling jobs and our footage contracts could adversely affect our financial position and our results of operations.

        We have historically derived a significant portion of our revenues from turnkey drilling contracts and we expect that they will represent a significant component of our future revenues. The occurrence of uninsured or under-insured losses or operating cost overruns on our turnkey jobs could have a material adverse effect on our financial position and results of operations. Under a typical turnkey drilling contract, we agree to drill a well for our customer to a specified depth and under specified conditions for a fixed price. We provide technical expertise and engineering services, as well as most of the equipment and drilling supplies required to drill the well. We often subcontract for related services, such as the provision of casing crews, cementing and well logging. Under typical turnkey drilling arrangements, we do not receive progress payments and are paid by our customer only after we have performed the terms of the drilling contract in full. For these reasons, the risk to us under a turnkey drilling contract is substantially greater than for a well drilled on a daywork basis, because we must

assume most of the risks associated with drilling operations that the operator generally assumes under a daywork contract, including the riskrisks of blowout, loss of hole, stuck drill pipe, machinery breakdowns, abnormal drilling conditions and risks associated with subcontractors' services, supplies, cost escalations and personnel. Similar to our turnkey contracts, under a footage contract we assume most of the risks associated with drilling operations that the operator generally assumes under a daywork contract.

Although we attempt to obtain insurance coverage to reduce certain of the risks inherent in our turnkey and footage drilling operations, adequate coverage may be unavailable in the future and we might have to bear the full cost of such risks, which could have an adverse effect on our financial condition and results of operation.

Our operations involve operating hazards, which if not insured or indemnified against, could adversely affect our results of operations and financial condition.

        Our operations are subject to the many hazards inherent in the contract land drilling business, including the risks of:

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blowouts;



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fires and explosions;



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loss of well control;



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collapse of the borehole;



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lost or stuck drill strings; and



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damage or loss from natural disasters.

        Any of these hazards can result in substantial liabilities or losses to us from, among other things:

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suspension of drilling operations;



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damage to, or destruction of, our property and equipment and that of others;



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personal injury and loss of life;



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damage to producing or potentially productive oil and gas formations through which we drill; and



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environmental damage.

        We seek to protect ourselves from some but not all operating hazards through insurance coverage. However, some risks are either not insurable or insurance is available only at rates that we consider uneconomical. Those risks include pollution liability in excess of relatively low limits. Depending on competitive conditions and other factors, we attempt to obtain contractual protection against uninsured operating risks from our customers. However, customers who provide contractual indemnification protection may not in all cases maintain adequate insurance to support their indemnification obligations. Our insurance or indemnification arrangements may not adequately protect us against liability or loss from all the hazards of our operations. The occurrence of a significant event that we have not fully insured or indemnified against or the failure of a customer to meet its indemnification obligations to us could materially and adversely affect our results of operations and financial condition. Furthermore, we may be unable to maintain adequate insurance in the future at rates we consider reasonable.

We face increased exposure to operating difficulties because we primarily focus on drilling for natural gas.

        We focus on obtainingMost of our drilling contracts fromare with exploration and production companies in search of natural gas in East, North and South Texas.gas. Drilling on land for natural gas generally occurs at deeper drilling depths than drilling for oil. Although deep-depth drilling exposes us to risks similar to risks encountered in shallow-depth drilling, the magnitude of the risk for deep-depth drilling is greater because of the higher costs and greater complexities involved in drilling deep wells. We generally do not insure risks related to operating difficulties other than blowouts. If we do not adequately insure the increased risk from blowouts or if our contractual indemnification rights are insufficient or unfulfilled,

our profitability and other results of operation and our financial condition could be adversely affected in the event we encounter blowouts or other significant operating difficulties while drilling at deepdeeper depths.

Our current primary focus on drilling for natural gas could place us at a competitive disadvantage if we changed our primary focus to drilling for oil.

        Our rig fleet consists of rigs capable of drilling on land at drilling depths of 8,0006,000 to 18,000 feet because most of our contracts are with customers drilling in search of natural gas, which generally occurs at deeper drilling depths than drilling in search of oil, which often occurs at drilling depths less than 8,0006,000 feet. Generally, deeperlarger drilling depth rigs capable of deep drilling generally incur higher mobilization costs than smaller drilling rigs drilling at shallower drilling depth rigs.depths. If our primary focus shifts from drilling for customers in search of natural gas to drilling for customers in search of oil, the majority of our rig fleet would be disadvantaged in competing for new oil drilling projects as compared to competitors that primarily use shallower drilling depth rigs when drilling in search of oil.

Our operations are subject to various laws and governmental regulations that could restrict our future operations and increase our operating costs.

        Many aspects of our operations are subject to various federal, state and local laws and governmental regulations, including laws and regulations governing:

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environmental quality;



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pollution control;



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remediation of contamination;



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preservation of natural resources; and



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worker safety.

        Our operations are subject to stringent laws and regulations relating to containment, disposal and controlling the discharge of hazardous oilfield waste and other non-hazardousnon hazardous waste material into the environment, requiring removal and cleanup under certain circumstances, or otherwise relating to the protection of the environment. In addition, our operations are often conducted in or near ecologically sensitive areas, such as wetlands, which are subject to special protective measures and which may expose us to additional operating costs and liabilities for accidental discharges of oil, gas, drilling fluids or contaminated water or for noncompliance with other aspects of applicable laws. We are also subject to the requirements of the federal Occupational Safety and Health Act ("OSHA") and comparable state statutes. The OSHA hazard communication standard, the Environmental Protection Agency "community right-to-know" regulations under Title III of the Federal Superfund Amendment and Reauthorization Act and comparable state statutes require us to organize and report information about the hazardous materials we use in our operations to employees, state and local government authorities and local citizens.

        Environmental laws and regulations are complex and subject to frequent change. In some cases, they can impose liability for the entire cost of cleanup on any responsible party without regard to negligence or fault and can impose liability on us for the conduct of others or conditions others have caused, or for our acts that complied with all applicable requirements when we performed them. We may also be exposed to environmental or other liabilities originating from businesses and assets which we purchased from others. Our compliance with amended, new or more stringent requirements, stricter interpretations of existing requirements or the future discovery of contamination may require us to make material expenditures or subject us to liabilities that we currently do not anticipate.

        In addition, our business depends on the demand for land drilling services from the oil and gas industry and, therefore, is affected by tax, environmental and other laws relating to the oil and gas industry generally, by changes in those laws and by changes in related administrative regulations. It is also possible that these laws and regulations may in the future add significantly to our operating costs or those of our customers or otherwise directly or indirectly affect our operations.

We could be adversely affected if shortages of equipment, supplies or personnel occur.

        From time to time there have been shortages of drilling equipment and supplies during periods of high demand which we believe could reoccur. Shortages could result in increased prices for drilling equipment or supplies that we may be unable to pass on to customers. In addition, during periods of shortages, the delivery times for equipment and supplies can be substantially longer. Any significant delays in our obtaining drilling equipment or supplies could limit drilling operations and jeopardize our relations with customers. In addition, shortages of drilling equipment or supplies could delay and adversely affect our ability to obtain new contracts for our rigs, which could have a material adverse effect on our financial condition and results of operations.

        Our operations require the services of employees having the technical training and experience necessary to obtain the proper operational results. As a result, our operations depend, to a considerable extent, on the continuing availability of such personnel. Shortages of qualified personnel are occurring in our industry. If we should suffer any material loss of personnel to competitors or be unable to employ additional or replacement personnel with the requisite level of training and experience to adequately operate our equipment, our operations could be materially and adversely affected. A significant increase in the wages paid by other employers could result in a reduction in our workforce, increases in wage rates, or both. The occurrence of either of these events for a significant period of time could have a material and adverse effect on our financial condition and results of operations.

If our independent auditor is unable to provide us with an unqualified attestation report as to the adequacy of our internal control over financial reporting as required by Section 404 of the Sarbanes-Oxley Act of 2002, investors could lose confidence in the reliability of our financial statements, which could result in a decrease in the value of our common stock.

        Under Section 404 of the Sarbanes-Oxley Act of 2002, we will be required to include in each of our future annual reports on Form 10-K a report containing our management's assessment of the effectiveness of our internal control over financial reporting and a related attestation of our independent auditors. This requirement will first apply to our annual report on Form 10-K for the fiscal year ending March 31, 2005. We are currently undertaking a comprehensive effort in preparation for compliance with Section 404. This effort includes the documentation, testing and review of our internal controls under the direction of our management. We have been making various changes to our internal control over financial reporting as a result of our review efforts. Although we have not identified any material weaknesses in our internal control over financial reporting, as defined by the Public Company Accounting Oversight Board, due to the number of controls to be examined, the complexity of the project, as well as the subjectivity involved in determining effectiveness of controls,

we cannot be certain that all our controls will be considered effective. In addition, the guidelines for the evaluation and attestation of internal control over financial reporting have only recently been finalized, and the evaluation and attestation processes are new and untested. Therefore, we can give no assurances that our internal control over financial reporting will satisfy the new regulatory requirements. If our independent auditor is unable to provide us with an unqualified attestation report on a timely basis as required by Section 404, investors could lose confidence in the reliability of our financial statements, which could result in a decrease in the value of our common stock.

Risk Relating to Our Capitalization and Organizational Documents

Our largest shareholders and our management control a majoritysignificant percentage of our common stock, and their interests may conflict with those of our other shareholders.

        As of June 30, 2004,January 31, 2005, our largest shareholder, WEDGE, beneficially owned 40.0%19.71% of our outstanding common stock and, together with our other largest shareholdersChesapeake Energy Corporation ("Chesapeake") and our officers and directors as a group, beneficially owned a total of approximately 70%41.47% of our outstanding common stock. WEDGE is selling 4,000,0005,000,000 shares of our common stock in this offering (4,687,302(5,787,500 shares if the underwriters exercise their over-allotment option in full) and has agreed to convert, pursuant to its terms, the $27 million in aggregate principal amount of our 6.75% convertible subordinated debentures that it holds into 6,264,501 shares of our common stock immediately prior to the closing of this offering. For each shareholder or group of shareholders, beneficial ownership and percentage ownership assumes the full conversion of our 6.75% convertible subordinated debentures into 6,496,519

shares of our common stock.. The following table shows, as of June 30, 2004,January 31, 2005, the beneficial ownership of these persons:

(1)

The number of shares and percentage shown for WEDGE (i) reflects 6,264,501 shares that WEDGE will acquire on conversion of the $27,000,000 aggregate principal amount of our 6.75% convertible subordinated debentures that WEDGE currently holds and has agreed to convert immediately prior to the closing of this offering and (ii) doesDoes not reflect the sale by WEDGE of any shares of our common stock pursuant to this offering. The percentages shown for the other shareholders have been adjusted to reflect the full conversion of the entire $28 million outstanding of our 6.75% convertible subordinated debentures into 6,496,519 shares of our common stock, but have not been adjusted to reflect the sale of any shares of our common stock pursuant to this offering.

(2)

In addition to the shares reflected in the table, Chesapeake has advised us that it intends to acquire up to 631,133 shares offered in this offering (up to 725,803 shares if the underwriters exercise their over-allotment option in full) in accordance with its preemptive rights that are applicable to this offering. See "Certain Relationships and Related Transactions—Transaction with Chesapeake Energy Corporation."

(3)

Includes options to purchase 1,000,001633,668 shares of common stock which are exercisable within 60 days of June 30, 2004.January 31, 2005.

        In some circumstances, if WEDGE were to act alone or in concert with a small number of these or other shareholders, they would be able to exercise substantial control over our affairs, including the election of our entire board of directors and, subject to the applicable provisions of the Texas Business Corporation Act, the disposition of any matter submitted to a vote of our shareholders.affairs. WEDGE currently has the right to nominate three personsone person for election to our board of directors, which as of the date of this prospectus consists of seven members. The interests of WEDGE and these other persons with respect to matters potentially or actually involving or affecting us, such as future acquisitions, financings and other corporate opportunities and attempts to acquire us, may conflict with the interests of our other shareholders.

Limited trading volume of our common stock may contribute to its price volatility.

        Our common stock is traded on the American Stock Exchange. During the three-month period from January 1, 2003 through June 30,ended December 31, 2004, the average daily trading volume of our common stock as reported by the American Stock Exchange was 23,897144,531 shares. There can be no assurance that a more active trading market in our common stock will develop as a result of this offering. As a result, relatively small trades may have a significant impact on the price of our common stock and, therefore, may contribute to the price volatility of our common stock. As a result, our common stock may be subject to greater price volatility than the stock market as a whole and comparable securities of other contract drilling service providers.

        The market price of our common stock has been, and may continue to be, volatile. For example, during ourfrom April 1, 2004 fiscal year,through January 31, 2005, the trading price of our common stock has ranged from $3.30$5.60 to $7.35$10.50 per share.

        Because of the limited trading market of our common stock and the price volatility of our common stock, you may be unable to sell shares of common stock when you desire or at a price you desire. The inability to sell your shares in a declining market because of such illiquidity or at a price you desire may substantially increase your risk of loss.

The market price of our common stock could decline following sales of substantial amounts of our common stock in the public markets.

        In addition to the 4,000,0005,000,000 shares to be sold by WEDGE in this offering (4,687,302(5,787,500 shares if the underwriters exercise their over-allotment option in full), our largest shareholders, WEDGE Chesapeake and Temple,Chesapeake, could sell a substantial number of shares of our common stock in the public market under exemptions afforded to affiliates under Rule 144 of the Securities Act of 1933, as amended, under an effectivea resale registration statement or over the American Stock Exchange. Such sales by our largest shareholders, sales by other securityholders or the perception that such sales might occur could have a material adverse effect on the price of our common stock or could impair our ability to obtain capital through an offering of equity securities.

We may issue preferred stock whose terms could adversely affect the voting power or value of our common stock.

        Our articles of incorporation authorize us to issue, without the approval of our shareholders, one or more classes or series of preferred stock having such designations, preferences, limitations and relative rights, including preferences over our common stock respecting dividends and distributions, as our board of directors may determine. The terms of one or more classes or series of preferred stock could adversely impact the voting power or value of our common stock. For example, we might grant holders of preferred stock the right to elect some number of our directors in all events or on the happening of specified events or the right to veto specified transactions. Similarly, the repurchase or redemption rights or liquidation preferences we might assign to holders of preferred stock could affect the residual value of the common stock.

Provisions in our organizational documents could delay or prevent a change in control of our company, even if that change would be beneficial to our shareholders.

        The existence of some provisions in our organizational documents could delay or prevent a change in control of our company, even if that change would be beneficial to our shareholders. Our articles of incorporation and bylaws contain provisions that may make acquiring control of our company difficult, including:

•

provisions regulating the ability of our shareholders to bring matters for action at annual meetings of our shareholders;



•

limitations on the ability of our shareholders to call a special meeting and act by written consent;



•

provisions dividing our board of directors into three classes elected for staggered terms; and



•

the authorization given to our board of directors to issue and set the terms of preferred stock.

FORWARD-LOOKING STATEMENTS

        We are including the following discussion to inform you generally of some of the risks and uncertainties that can affect our company and to take advantage of the "safe harbor" protection for forward-looking statements that applicable federal securities law affords.

        This prospectus contains forward-looking statements, including statements that include projections and estimates concerning the timing and success of specific projects and our future backlog, revenues, income and capital spending. Forward-looking statements are generally accompanied by words such as "estimate," "project," "predict," "believe," "expect," "anticipate," "plan," "intend," "seek," "will," "should," "goal" or other words that convey the uncertainty of future events or outcomes. These forward-looking statements speak only as of the date of this prospectus. We disclaim any obligation to update these statements, and we caution you not to rely on them unduly. We have based these forward-looking statements on our current expectations and assumptions about future events. While our management considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks, contingencies and uncertainties, most of which are difficult to predict and many of which are beyond our control. These risks, contingencies and uncertainties relate to, among other matters, the following:

•

general economic and business conditions and industry trends;



•

the continued strength of the contract land drilling industry in the geographic areas where we operate;



•

levels and volatility of oil an gas prices;



•

decisions about onshore exploration and development projects to be made by oil and gas companies;



•

the highly competitive nature of our businesses;



•

the success or failure of our acquisition strategy, including our ability to finance acquisitions and manage growth;



•

our future financial performance, including availability, terms and deployment of capital;



•

the continued availability of qualified personnel; and



•

changes in, or our failure or inability to comply with, government regulations, including those relating to the environment.

        We believe the items we have outlined above are important factors that could cause our actual results to differ materially from those expressed in a forward-looking statement contained in this prospectus. We have discussed many of these factors in more detail elsewhere in this prospectus. These factors are not necessarily all the important factors that could affect us. Unpredictable or unknown factors we have not discussed in this prospectus could also have material adverse effects on actual results of matters that are the subject of our forward-looking statements. We do not intend to update our description of important factors each time a potential important factor arises. We advise you that you should (1) be aware that important factors not referred to above could affect the accuracy of our forward-looking statements and (2) use caution and common sense when considering our forward-looking statements. Also, please read the "Risk Factors" section of this prospectus.

USE OF PROCEEDS

        We estimate that we will receive net proceeds of $                                           million (assuming that Chesapeake will exercise its preemptive rights with respect to all the shares allocated to it) from our sale of 4,000,0005,000,000 shares of common stock, after deducting the underwriting discount and the estimated expenses of this offering. See "Underwriting—Commissions and Expenses." If the underwriters' over-allotment option to purchase an additional 600,000787,500 shares from us is exercised in full, we estimate that our net proceeds will be $                                           million (assuming that Chesapeake will exercise its preemptive rights with respect to all the shares allocated to it).million. We will not receive any of the proceeds from the sale of our common stock by the selling shareholders.

        We intend to use approximately $20 million of our net proceeds from this offering to (1) retirefund the completion of the construction of two rigs from new and used components to be added to our note payable to Merrill Lynch Capitalfleet and (2) repay approximately $20 million of indebtedness we incurred under the acquisition facility portion of the new credit facility we entered into in the principal amount of $12.6 million as of June 30, 2004, which is due in December 2007 and bears interest at a floating rate equal to the three-month LIBOR rate (1.58% at June 30, 2004) plus 385 basis points, (2) retire our note payable to Frost National Bank in the principal amount of $4.1 million as of June 30, 2004, which is due in August 2007 and bears interest at the prime rate (4.25% at June 30, 2004) plus 1% and (3) retire our note payable to Frost National Bank in the principal amount of $2.9 million as of June 30, 2004, which is due in March 2007 and bears interest at the prime rate plus 1%. Our note payable to Frost National Bank which is due in March 2007 was incurred within the last year, and we used the proceeds from our issuance of that note in December 2003 and February 2004 to purchase a rig (Rig #4) we had been leasing under an operating lease.

October 2004. We expect to use anyour remaining net proceeds from this offering for general corporate purposes, includingwhich may include funding capital expenditures for rig upgrades.

        We expect the fundingtotal amount to be spent on completion of working capital requirementsconstruction of the two rigs to be added to our fleet to be approximately $12.2 million. We anticipate completing construction of these rigs in May and capital expenditures.June 2005.

        Of the indebtedness outstanding under the acquisition facility, we incurred:

•

$28.0 million in November 2004 to fund our acquisition of the assets of Wolverine Drilling and payment of the cash consideration under two related noncompetition agreements; and



•

$7.2 million in December 2004 to fund our acquisition of the assets of Allen Drilling.

        The indebtedness we incurred under the acquisition facility in November and December 2004 is due in monthly installments, which commenced on the first business day of January 2005, based on a 72-month amortization schedule, with all remaining unpaid principal being due on December 1, 2007. All the indebtedness under the acquisition facility bears interest at Frost National Bank's prime rate (5.25% as of January 31, 2005). For additional information regarding our new credit facility, see "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources."

PRICE RANGE OF COMMON STOCK

        As of JulyJanuary 31, 2004, 27,305,1262005, 38,914,978 shares of our common stock were outstanding, held by approximately 618590 shareholders of record. The number of record holders does not necessarily bear any relationship to the number of beneficial owners of our common stock.

        Our common stock trades on The American Stock Exchange under the symbol "PDC." The following table sets forth, for each of the periods indicated, the high and low sales prices per share on The American Stock Exchange:

        The last reported sale price for our common stock on the American Stock Exchange on August 3, 2004February 4, 2005 was $7.35$10.62 per share.

DIVIDEND POLICY

        We have not paid or declared any dividends on our common stock since our inception and currently intend to retain earnings to fund our working capital needs and growth opportunities. Any future dividends will be at the discretion of our board of directors after taking into account various factors it deems relevant, including our financial condition and performance, cash needs, income tax consequences and the restrictions Texas and other applicable laws and our debt arrangements then impose. Our current debt arrangements include provisions that (1) generally prohibit us from paying dividends other than dividends on our preferred stock. We currently have no preferredcommon stock outstanding.and (2) limit our subsidiaries' ability to pay dividends or make loans or advances to us.

CAPITALIZATION

        The following table sets forth our cash and cash equivalents, debt and total capitalization as of June 30,December 31, 2004 on an actual basis, and as adjusted for (1) the full conversion of our 6.75% convertible subordinated debentures due July 3, 2007, (2) our sale of 4,000,0005,000,000 shares of common stock in this offering, assuming the underwriters' over-allotment option is not exercised and assuming that Chesapeake will acquire 631,133 shares in this offering in satisfaction of its preemptive rights that are applicable to this offering, as described in "Certain Relationships and Related Transactions—Transaction with Chesapeake Energy Corporation," and (3)(2) the application of the estimated (based on the current market prices of our common stock) net proceeds from this offering after deducting the underwriting discount and commissions and our estimated offering expenses. You should read this table together with "Management's Discussion and Analysis of Financial Condition and Results of Operations" beginning on page 2120 of this prospectus and the historical consolidated financial statements and related notes included in this prospectus.

SELECTED FINANCIAL DATA

        The following table sets forth our selected financial data as of and for each of the fiscal years and interim periods indicated and is derived from our historical audited consolidated financial statements for the fiscal years indicated and from our historical unaudited consolidated financial statements for the interim periods indicated. You should review this information in conjunction with "Management's Discussion and Analysis of Financial Condition and Results of Operations" beginning on page 2120 of this prospectus and the consolidatedour historical financial statements and related notes included in this prospectus.

Refer to Note 2 of theour historical consolidated financial statements for information on acquisitions.acquisitions and the pro forma financial statements (and notes thereto) reflecting our acquisitions of the assets of Wolverine Drilling and Allen Drilling contained in this prospectus.

SUPPLEMENTARY FINANCIAL INFORMATION

        The following table summarizes our quarterly financial data for our first quarter of our fiscal year ended March 31, 2005 and for the fiscal years ended March 31, 2004 and 2003 (in thousands, except per share data):

MANAGEMENT'S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

        Statements we make in the following discussion which express a belief, expectation or intention, as well as those that are not historical fact, are forward-looking statements that are subject to risks, uncertainties and assumptions. Our actual results, performance or achievements, or industry results, could differ materially from those we express in the following discussion as a result of a variety of factors, including general economic and business conditions and industry trends, the continued strength or weakness of the contract land drilling industry in the geographic areas in which we operate, decisions about onshore exploration and development projects to be made by oil and gas companies, the highly competitive nature of our business, our future financial performance, including availability, terms and deployment of capital, the continued availability of qualified personnel, and changes in, or our failure or inability to comply with, government regulations, including those relating to the environment.

Company Overview

        Pioneer provides contract land drilling services to independent and major oil and gas exploration and production companies. In addition to our drilling rigs, we provide the drilling crews and most of the ancillary equipment needed to operate our drilling rigs. We have focused our operations in theselected oil and natural gas production regions of South, East and North Texas.in the United States. Our company was incorporated in 1979 as the successor to a business that had been operating since 1968. We conduct our operations through our principal operating subsidiary, Pioneer Drilling Services, Ltd. We are an oil and gas services company. We do not invest in oil and natural gas properties. The drilling activity of our customers is highly dependent on the current price of oil and natural gas.

        Our business strategy is to own and operate a high-quality fleet of land drilling rigs in active drilling markets, and position ourselves to maximize rig utilization and dayrates and to enhance shareholder value. We intend to continue making additions to our drilling fleet, either through acquisitions of businesses or selected assets or through the construction of refurbished drilling rigs.

        Over the past five fiscal years,Since September 1999, we have significantly expanded our fleet of drilling rigs through acquisitions and the construction of new and refurbished rigs. As of MarchDecember 31, 2004, our rig fleet consisted of 3549 land drilling rigs that drill in depth ranges between 8,0006,000 and 18,000 feet. As of MarchJanuary 31, 2004, fourteen of our2005, we had 15 rigs were operating in South Texas, 17 in East Texas, and four in North Texas.Texas, five in Western Oklahoma and eight in the Rocky Mountains. We actively market all of these rigs. We completed construction of our 36th rig in late May 2004 and began moving it to its first drilling location in South Texas on May 28, 2004. Subject to obtaining satisfactory financing, we anticipate continued growth of our rig fleet in fiscal 2005. However, we2006. We are not currently committed to any acquisitions.constructing a 1,000-horse power mechanical rig from new and used components.

        We earn our revenues by drilling oil and gas wells.wells for our customers. We obtain our contracts for drilling oil and gas wells either through competitive bidding or through direct negotiations with customers. Our drilling contracts generally provide for compensation on either a daywork, turnkey or footage basis. Contract terms we offer generally depend on the complexity and risk of operations, the on-site drilling conditions, the type of equipment used and the anticipated duration of the work to be performed. Generally, our contracts provide for the drilling of a single well and typically permit the customer to terminate on short notice.

        A significant performance measurement in our industry is rig utilization. We compute rig utilization rates by dividing revenue days by total available days during a period. Total available days are the number of calendar days during the period that we have owned the rig. Revenue days for each rig are days when the rig is earning revenues under a contract, which is usually a period from the date the rig begins moving to the drilling location until the rig is released from the contract. On daywork contracts, during the mobilization period we typically earn a fixed amount of revenue based on the mobilization rate stated in the contract. We attempt to set the mobilization rate at an amount equal to our external

costs for the move plus our internal costs during the mobilization period. We begin

earning our contracted daywork rate when we begin drilling the well. Occasionally, in periods of increased demand, some of our contracts will provide for the trucking costs to be paid by the customer and we will receive a reduced dayrate during the mobilization period.

        For the threenine months ended June 30,December 31, 2004 and 2003 and for the three years ended March 31, 2004, our rig utilization, revenue days and number of rigs were as follows:

        The reasons for the increase in the number of revenue days in 2004 over 2003 and 2002 are the increase in size of our rig fleet and the improvement in our overall rig utilization rate.rate due to improved market conditions. The reasons for the increase in the number of revenue days in the first quarternine months of 2004 over the first quarternine months of 2003 are the increase in size of our rig fleet from 2528 at June 30,December 31, 2003 to 3649 at June 30,December 31, 2004 and the improvement in our overall rig utilization rate. For the remainder of fiscal 2005 and through fiscal 2006, we anticipate continued growth in revenue days and maintaining relatively high utilization rates.

        WeIn addition to high commodity prices, we attribute our relatively high utilization rates to a strong sales effort, quality equipment, good field and operations personnel, a disciplined safety approach, and our generally successful performance of turnkey operations. Turnkey contracts currently account for approximately one-third25% of our contracts. Turnkey contracts provide us with the opportunity to keep our rigs working in periods of lower demand and improve our profitability, but at an increased risk. As was the case for several turnkey contracts under which we performed during the quarternine months ended June 30,December 31, 2004, a turnkey contract may not be profitable if it cannot be completed successfully without unanticipated complications.

        We devote substantial resources to maintaining and upgrading our rig fleet. During our fiscal year 2004, we removed three rigs from service for approximately three weeks each, in order to perform upgrades. In the short term, these actions resulted in fewer revenue days and slightly lower utilization; however, in the long term, we believe the upgrades will help the marketability of the rigs and improve their operating performance. We are currently performing, between contracts or as necessary, safety and equipment upgrades to the eight12 rigs we acquired in MarchNovember and December 2004.

Market Conditions in Our Industry

        The United States contract land drilling services industry is highly cyclical. Volatility in oil and gas prices can produce wide swings in the levels of overall drilling activity in the markets we serve and affect the demand for our drilling services and the dayrates we can charge for our rigs. The availability of financing sources, past trends in oil and gas prices and the outlook for future oil and gas prices strongly influence the number of wells oil and gas exploration and production companies decide to drill.

        For the three months ended March 31, 2004, the average weekly spot price for West Texas Intermediate crude oil was $35.08, the average weekly spot price for Henry Hub natural gas was $5.61 and the average weekly Baker Hughes land rig count was 1,002. For the three months ended June 30, 2004, the average weekly spot price for West Texas Intermediate crude oil was $38.30, the average weekly spot price for Henry Hub natural gas was $6.06 and the average weekly Baker Hughes land rig count was 1,048. On July 23, 2004, the spot price for West Texas Intermediate crude oil was $41.76, the spot price for Henry Hub natural gas was $5.99. For the week of July 16, 2004, the Baker Hughes land rig count was 1,097, a 13.0% increase from 967 as of the corresponding week in 2003.

The average weekly spot prices of West Texas Intermediate crude oil and Henry Hub natural gas and the average weekly domestic land rig count, per the Baker Hughes land rig count, for the nine

months ended December 31, 2004 and each of our five most recent fiscal years in the previous six yearsperiod ended June 30,March 31, 2004 were:

        The decline inOn January 31, 2005, the spot price for West Texas Intermediate crude oil was $48.20 and the spot price for Henry Hub natural gas priceswas $6.16. For the week of January 28, 2005, the Baker Hughes land rig count was 1,130, a 16% increase from mid-2001 to mid-2002 resulted973 as of the corresponding week in a reduction in the demand for contract land drilling services, which resulted in a substantial reduction in the rates land drilling companies were able to obtain for their services. While oil and natural gas prices have recovered in recent months, drilling activity has not yet recovered to a level at which we are able to significantly improve our revenue rates and profitability.2004.

        We believe capital spent on incremental natural gas production will be driven by an increase in hydrocarbon demand as well as shortages in supply of natural gas. The Energy Information Agency recently estimated that U.S. consumption of natural gas exceeded U.S. domestic productive capacity by 20%15% in 20022003 and forecasts that U.S. consumption of natural gas will exceed U.S. domestic productive capacity by 28%25% by 2010. Most of this difference is expected to be driven by the growth in consumption by electric power generators, as a significant amount of natural gas-fired power generation capacity has been constructed within the last five years and older, less-efficient power generation capacity, not fired by natural gas, is expected to be decommissioned. In addition, a study published by the National Petroleum Council in September 2003 concluded from drilling and production data over the preceding 10 years that average "initial production rates from new wells have been sustained through the use of advanced technology; however, production declines from these initial rates have increased significantly; and recoverable volumes from new wells drilled in mature producing basins have declined over time. Without the benefit of new drilling, indigenous supplies have reached a point at which U.S. production declines by 25% to 30% each year. Eighty percent of gas production in 10 years will be from wells yet to be drilled." We believe all of these factors tend to support a higher natural gas price environment, which should create strong incentives for oil and natural gas exploration and production companies to increase drilling activity in North America. Consequently, these factors may result in higher rig dayrates and rig utilization.

        During fiscal 2004, 2003 and 2002 and the first threenine months of fiscal 2005, substantially all the wells we drilled for our customers were drilled in search of natural gas because of the depth capacity of our rigs and the gas rich areas in which we operate. Although we have recently diversified our operations somewhat with the November 2004 acquisition of seven drilling rigs from Wolverine Drilling, with five of those rigs employed in search of oil in the Williston Basin of the Rocky Mountains, our customers remain primarily focused on drilling for natural gas. Natural gas reserves are typically found in deeper geological formations and generally require premium equipment and quality crews to drill the wells.

Critical Accounting Policies and Estimates

        Revenue and cost recognition—Cost Recognition—We earn our revenues by drilling oil and gas wells for our customers under daywork, turnkey or footage contracts, which usually provide for the drilling of a single well. We recognize revenues on daywork contracts for the days completed based on the dayrate each contract specifies. We recognize revenues from our turnkey and footage contracts on the percentage-of completionpercentage-of-completion method for the days completed, based on the contract amount divided by our estimate of the number of days to complete each contract. Contract drilling in progress represents revenues we have recognized in excess of amounts billed on contracts in progress. Individual contracts are usually completed in less than 60 days. The risks to us under a turnkey contract, and to a lesser extent under footage contracts, are substantially greater than on a contract drilled on a daywork basis.

This is primarily because, under a turnkey contract, we assume most of the risks associated with drilling operations generally assumed by the operator in a daywork contract, including the risks of blowout, loss

of hole, stuck drill pipe, machinery breakdowns and abnormal drilling conditions, as well as risks associated with subcontractors' services, supplies, cost escalations and personnel operations.

        Our management has determined that it is appropriate to use the percentage-of-completion method to recognize revenue on our turnkey and footage contracts. Although our turnkey and footage contracts do not have express terms that provide us with rights to receive payment for the work that we perform prior to drilling wells to the agreed onagreed-on depth, we use this method because, as provided in applicable accounting literature, we believe we achieve a continuous sale for our work-in-progress and we believe, under applicable state law, we ultimately could recover the fair value of our work-in-progress even in the event we were unable to drill to the agreed onagreed-on depth in breach of the applicable contract. However, ultimate recovery of that value, in the event we were unable to drill to the agreed on depth in breach of the contract, would be subject to negotiations with the customer and the possibility of litigation.

        If a customer defaults on its payment obligation to us under a turnkey or footage contract, we would need to rely on applicable law to enforce our lien rights, because our turnkey and footage contracts do not expressly grant to us a security interest in the work we have completed under the contract and we have no ownership rights in the work-in-progress or completed drilling work, except any rights arising under the applicable lien statute on foreclosure. If we were unable to drill to the agreed on depth in breach of the contract, we also would need to rely on equitable remedies outside of the contract, includingquantum meruit, available in applicable courts to recover the fair value of our work-in-progress under a turnkey or footage contract.

        We accrue estimated contract costs on turnkey and footage contracts for each day of work completed based on our estimate of the total costs to complete the contract divided by our estimate of the number of days to complete the contract. Contract costs include labor, materials, supplies, repairs and maintenance, operating overhead allocations and allocations of depreciation and amortization expense. In addition, the occurrence of uninsured or under-insured losses or operating cost overruns on our turnkey and footage contracts could have a material adverse effect on our financial position and results of operations. Therefore, our actual results could differ significantly if our cost estimates are later revised from our original estimates for contracts in progress at the end of a reporting period which were not completed prior to the release of our financial statements.

        Asset impairments—Impairments—We assess the impairment of property and equipment whenever events or circumstances indicate that the carrying value may not be recoverable. Factors that we consider important and which could trigger an impairment review would be our customers' financial condition and any significant negative industry or economic trends. More specifically, among other things, we consider our contract revenue rates, our rig utilizations rates, cash flows from our drilling rigs, current oil and gas prices, industry analysts' outlook for the industry and their view of our customers' access to debt or equity, discussions with major industry suppliers, discussions with officers of our primary lender regarding their experiences and expectations for oil and gas operators in our areas of operations and the trends in the price of used drilling equipment observed by our management. If a review of our drilling rigs indicates that our carrying value exceeds the estimated undiscounted future cash flows, we are required under applicable accounting standards to write down the drilling equipment to its fair market value. A one percent write-down in the cost of our drilling equipment, at March 31, 2004, would have resulted in a corresponding increase in our net loss of approximately $962,000 for our fiscal year ended March 31, 2004. A one percent write-down in the cost of our drilling equipment, at June 30,December 31, 2004, would have resulted in a corresponding decrease in our net earnings of approximately $994,000$1,324,000 for the threenine months ended June 30,December 31, 2004.

        Deferred taxes—Taxes—We provide deferred taxes for net operating loss carryforwards and for the basis difference in our property and equipment between financial reporting and tax reporting purposes. For property and equipment, basis differences arise from differences in depreciation periods and methods

and the value of assets acquired in a business acquisition where we acquire an entity rather than just its assets. For financial reporting purposes, we depreciate the various components of our drilling rigs over eight to 15 years and refurbishments over three years, while federal income tax rules require that we depreciate drilling rigs and refurbishments over five years. Therefore, in the first five years of our ownership of a drilling rig, our tax depreciation exceeds our financial reporting depreciation, resulting in our providing deferred taxes on this depreciation difference. After five years, financial reporting depreciation exceeds tax depreciation, and the deferred tax liability begins to reverse.

        Accounting estimatesEstimates—We consider the recognition of revenues and costs on turnkey and footage contracts critical accounting estimates. On these types of contracts, we are required to estimate the number of days it will require for us to complete the contract and our total cost to complete the contract. Our actual costs could substantially exceed our estimated costs if we encounter problems such as lost circulation, stuck drill pipe or an underground blowout on contracts still in progress subsequent to the release of the financial statements.

        We receive payment under turnkey and footage contracts when we deliver to our customer a well completed to the depth specified in the contract, unless the customer authorizes us to drill to a shallower depth. Since 1995, when current management joined our company, we have completed all our turnkey or footage contracts. Although our initial cost estimates for turnkey and footage contracts do not include cost estimates for risks such as stuck drill pipe or loss of circulation, we believe that our experienced management team, our knowledge of geologic formations in our areas of operations, the condition of our drilling equipment and our experienced crews enable us to make reasonably dependable cost estimates and complete contracts according to our drilling plan. While we do bear the risk of loss for cost overruns and other events that are not specifically provided for in our initial cost estimates, our pricing of turnkey and footage contracts takes such risks into consideration. When we encounter, during the course of our drilling operations, conditions unforeseen in the preparation of our original cost estimate, we immediately increase our cost estimate for the additional costs to complete the contracts. If we anticipate a loss on a contract in progress at the end of a reporting period due to a change in our cost estimate, we immediately accrue the entire amount of the estimated loss including all costs that are included in our revised estimated cost to complete that contract in our consolidated statement of operations for that reporting period. During fiscal 2004, we experienced losses on eight of the 105 turnkey and footage contracts completed, with losses exceeding $25,000 on eightsix contracts, including two contracts with losses exceeding $100,000. During the threenine months ended June 30,December 31, 2004, we experienced losses on five14 of the 45128 turnkey and footage contracts completed, with losses exceeding $25,000 on fournine contracts and losses exceeding $100,000 on one contract.four contracts. We are more likely to encounter losses on turnkey and footage contracts in years in which revenue rates are lower for all types of contracts. During periods of reduced demand for drilling rigs, our overall profitability on turnkey and footage contracts has historically exceeded our profitability on daywork contracts.

        Revenues and costs during a reporting period could be affected for contracts in progress at the end of a reporting period which have not been completed before our financial statements for that period are released. All but one of our turnkey contracts in progress at March 31, 2004 were completed prior to the release of our fiscal 2004 financial statements included in this prospectus. All but three of our turnkey and footage contracts in progress at June 30,December 31, 2004 were completed prior to the release of our first quarter 2005the most recent interim-period financial statements included in this prospectus. At March 31, 2004, our contract drilling in progress totaled approximately $9,131,000. Of that amount accrued, turnkey and footage contract revenues were approximately $7,683,000. The remaining balance of approximately $1,448,000 relates to the revenue recognized but not yet billed on daywork contracts in progress at March 31, 2004. At June 30,December 31, 2004, our contract drilling in progress totaled approximately $10,461,000,

$7,351,000, of which turnkey and footage contract revenues were approximately $8,886,000$2,547,000 and daywork contract revenues were approximately $1,575,000.$4,804,000.

        We estimate an allowance for doubtful accounts based on the creditworthiness of our customers as well as general economic conditions. We evaluate the creditworthiness of our customers based on information obtained from major industry suppliers, current prices of oil and gas and any past experience we have with the customer. Consequently, an adverse change in those factors could affect our estimate of our allowance for doubtful accounts. In some instances, we require new customers to establish escrow accounts or make prepayments. We typically invoice our customers at 15-day intervals during the performance of daywork contracts and upon completion of the daywork contract. Turnkey and footage contracts are invoiced upon completion of the contract. Our typical contract provides for payment of invoices in 10 to 30 days. We generally do not extend payment terms beyond 30 days and have not extended payment terms beyond 60 days for any of our contracts in the last three fiscal years. We established an allowance for doubtful accounts of $452,000 at December 31, 2004, an increase of $342,000 from $110,000 at March 31, 2004.

        Another critical estimate is our determination of the useful lives of our depreciable assets, which directly affects our determination of depreciation expense and deferred taxes. A decrease in the useful life of our drilling equipment would increase depreciation expense and reduce deferred taxes. We provide for depreciation of our drilling, transportation and other equipment on a straight-line method over useful lives that we have estimated and that range from three to 15 years. We record the same depreciation expense whether a rig is idle or working. Our estimates of the useful lives of our drilling, transportation and other equipment are based on our more than 35 years of experience in the drilling industry with similar equipment.

        OtherOur other accrued expenses in ouras of December 31, 2004 and March 31, 2004 financial statements include an accrualaccruals of approximately $1,232,000 and $680,000, for costs incurred under the self-insurance portion of our health insurance and under our workers' compensation insurance. Other accrued expenses in our June 30, 2004 financial statements include an accrual of approximately $705,000respectively, for costs incurred under the self-insurance portion of our health insurance and under our workers' compensation insurance. We have a deductible of (1) $100,000 per covered individual per year under the health insurance and (2) $250,000 per occurrence under our workers' compensation insurance.insurance, except in North Dakota where the deductible is $100,000. We accrue for these costs as claims are incurred based on cost estimates established for each claim by the insurance companies providing the administrative services for processing the claims, including an estimate for incurred but not reported claims, estimates for claims paid directly by us, our estimate of the administrative costs associated with these claims and our historical experience with these types of claims.

Liquidity and Capital Resources

Sources of Capital Resources

        Our rig fleet has grown from eightsix rigs in September 1999 to 49 rigs as of August 1, 2000 to 35 rigs as of MarchDecember 31, 2004 (36 rigs as of June 30, 2004).2004. We have financed this growth with a combination of debt and equity financing. We have raised additional equity or used equity for growth six times since January 2000 and have increased our long-term debt from approximately $3,909,000 at June 30, 2000 to approximately $48,500,000 atAt March 31, 2004, ($47,600,000our total debt to total capitalization was approximately 41% (21% at June 30,December 31, 2004). We plan to continue to grow our rig fleet. We believe that near-termour growth will require the use of equity financing, rather than additionalin addition to debt. At March 31, 2004, our total debt to total capital was approximately 41% (40% at June 30, 2004). Due to the volatility in our industry, we are reluctant to take on substantial additional debt at this time. However, our ability to continue funding our growth through the issuance of shares of our common stock is uncertain, as our common stock is not heavily traded and the market price for our common stock has been volatile in recent periods.

        On February 20, 2004, we sold 4,400,000 shares of our common stock at $5.40 per share in a private placement to accredited investors for $23,760,000 in proceeds, before related offering expenses.

        On August 11, 2004, we also sold 4,000,000 shares of our common stock at approximately $6.61 per share, net of underwriters' commissions, pursuant to a public offering we registered with the SEC under a registration statement filed on Form S-1. On August 31, 2004, we sold 600,000 additional

shares of our common stock at approximately $6.61 per share, net of underwriters' commissions, pursuant to the underwriters' exercise of an over-allotment option granted in connection with that public offering.

        On October 29, 2004, we entered into a $47,000,000 credit facility with a group of lenders consisting of a $7,000,000 revolving line and letter of credit facility and a $40,000,000 acquisition facility for the acquisition of drilling rigs, rig transportation equipment and associated equipment. Frost National Bank is the administrative agent and lead arranger under the new credit facility, and the lenders include Frost National Bank, the Bank of Scotland and Zions First National Bank. Borrowings under the new credit facility bear interest at a rate equal to Frost National Bank's prime rate (5.25% at January 31, 2005) and are secured by most of our assets, including all our drilling rigs, associated equipment and receivables. As described below, we have borrowed $35,200,000 of the amount available under the acquisition facility and we have used approximately $2,800,000 of availability under the revolving line and letter of credit facility through the issuance of letters of credit in the ordinary course of business. The remaining approximately $4,800,000 and $4,200,000 of availability under the acquisition facility and the revolving line and letter of credit facility, respectively, should remain available to us until those facilities mature in October 2006 and October 2005, respectively.

Uses of Capital Resources

        In May 2003, we added one refurbished 18,000-foot SCR land drilling rig at a cost of approximately $7,300,000. On August 1, 2003, we purchased two land drilling rigs, associated spare parts and equipment and vehicles from Texas Interstate Drilling Company, L. P. for $2,500,000 in cash and the issuance of 477,000 shares of our common stock valued at $4.45 per share. On August 26, 2003, we purchased a 14,000-foot mechanical rig for $2,925,661 in cash. After accepting delivery of the rig, we spent approximately $2,400,000 upgrading the rig before placing it in service. On December 15, 2003, we acquired a rig for approximately $3,770,000 that we had previously been leasing.

        On March 2, 2004, we acquired 23 used rig hauling trucks and associated trailers and equipment from A&R Trejo Trucking for $1,200,000. On March 4, 2004, we acquired a seven-rig drilling fleet from Sawyer Drilling & Service, Inc. for $12,000,000. On March 12, 2004, we acquired one drilling rig from SEDCO Drilling Co., Ltd. for $2,015,000. These acquisitions were funded with proceeds from the February 20, 2004 sale of our common stock.

        In late May 2004, we completed constructing, primarily from used components, a 1,000-hp electric drilling rig. As of March 31, 2004, we hadWe incurred approximately $2,800,000$4,900,000 of construction costs on this rig.

        In November 2004, we acquired a fleet of seven drilling rigs and related equipment from Wolverine Drilling, obtained noncompetition agreements from the two stockholders of Wolverine Drilling and purchased a 4.7-acre rig storage and anticipatemaintenance yard in Kenmore, North Dakota for total consideration of $28,000,000 in cash. In December 2004, we acquired a fleet of five drilling rigs and related equipment and a 17-acre rig storage and maintenance yard located in Woodward, Oklahoma from Allen Drilling for total consideration of $7,200,000 in cash. We also obtained a noncompetition agreement from the President of Allen Drilling for additional relatedconsideration to be paid over the next five years. We funded the purchase price for each of these acquisitions with borrowings under our new credit facility aggregating $35,200,000.

        In December 2004 we also completed constructing, from new and used components, a 1000-horse power electric drilling rig, which we have designated as Rig No. 38. We incurred approximately $5,800,000 in rig construction costs of approximately $2,547,000.for that rig. We mobilized Rig No. 38 to Utah in December 2004, where it began moving it to its first drilling location on May 28, 2004. For fiscaloperating under a one-year daywork contract in January 2005.

        In January 2005, we project regular capital expendituresbegan constructing, from new and used components, a 1,000-horse power mechanical drilling rig. We estimate we will incur approximately $5,500,000 of construction costs for

that rig. We expect to be approximately $10,200,000complete construction of the rig in March 2005. We have also begun ordering components for the construction of two 1000-horse power SCR electric rigs at an estimated cost of $6,100,000 each. Construction of these rigs is subject to obtaining adequate financing.

        For the three and rig upgrade expenditures to be approximately $4,500,000. These regular capital expenditures and rig upgrade capital expenditures are expected to be funded primarily from operating cash flow.

        In fiscalnine months ended December 31, 2004, the additions to our property and equipment totaled $44,844,745. Additions consisted of the following:

(1)

Includes capitalized interest costs of $106,395.$0 for the three months and $28,740 for the nine months ended December 31, 2004.

        For the three months ended June 30, 2004,remainder of fiscal 2005, we project regular capital expenditures (excluding construction costs to complete the additions to our property and equipment were $8,415,522. Additions consistedconstruction of the following:three rigs referred to above) to be approximately $6,000,000, including approximately $1,800,000 for rig upgrade expenditures. We expect to fund these capital expenditures primarily from operating cash flow.

(1)

Includes capitalized interest costs of $28,740.

Working Capital

        Our working capital decreased to $6,028,018 at March 31, 2004 from $11,144,309 at March 31, 2003. Our current ratio, which we calculate by dividing our current assets by our current liabilities, was 1.27 at March 31, 2004 compared to 1.55 at March 31, 2003. The principal reason for the decrease in our working capital at March 31, 2004 was our use of approximately $3,400,000 of working capital

toward the purchase of drilling equipment. We used substantially all the $20,000,000 in proceeds from the shares of common stock we sold in a private placement to Chesapeake on March 31, 2003 to expand our rig fleet or reduce debt we incurred to expand our rig fleet. We have used approximately $17,000,000 of the funds we raised in February 2004 to expand our rig fleet or acquire other equipment.

        Our working capital increased to $11,842,627 at December 31, 2004 from $6,028,018 at March 31, 2004. Our current ratio, which we calculate by dividing our current assets by our current liabilities, was 1.48 at December 31, 2004, compared to 1.27 at March 31, 2004. The principal reason for the increase in our working capital at December 31, 2004 was our August 2004 public offering of common stock, in which we raised proceeds of approximately $29,700,000. Approximately $18,800,000 of those proceeds was used to retire substantially all our long-term debt as of August 2004.

        Our operations have historically generated sufficient cash flow to meet our requirements for debt service and equipment expenditures even(excluding rig and other major equipment acquisitions). However, during periods of industry downturns. During periods when a higher percentage of our contracts are turnkey and footage contracts, our short-term working capital needs could increase. The significant improvement in operating cash flow for the nine months ended December 31, 2004 over December 31, 2003 is due primarily to the approximately $7,500,000 overall improvement in net earnings, components of which are discussed in "—Results of Operations." That improvement was net of approximately $4,500,000 increase in noncash depreciation and amortization expense. If necessary, we can defer rig upgrades to improve our cash position. We have available a $2,500,000believe our cash generated by operations and our ability to borrow the currently unused portion of our line of credit for short-term cash requirements. We did not make any borrowings under the lineand letter of credit during fiscal 2004. We have used debt and equityfacility of approximately $4,200,000, which takes into account reductions for approximately $2,800,000 of outstanding letters of credit as of January 31, 2004, should allow us to financemeet our long-term growth strategy to increase the size of our rig fleet. During periods of improved revenue rates, we believe we can generate cash flows in excess of our normal cash requirements.routine financial obligations.

        The changes in the components of our working capital at March 31, 2004 from March 31, 2003 were as follows:

        The large cash balance at March 31, 2003 was due to our sale of $20,000,000 of equity on March 31, 2003, of which $14,000,000 was in the March 31, 2003 cash balance. The $14,000,000 was used during fiscal 2004 to purchase drilling rigs and equipment.

        The increase in our receivables at March 31, 2004 from March 31, 2003 was due to our operating eleven additional rigs in the quarter ended March 31, 2004, including an approximately $3,693,000 increase in contract drilling in progress related to turnkey contracts, and an improvement in revenue rates in fiscal 2004 over fiscal 2003.

        Substantially all our prepaid expenses at March 31, 2004 consisted of prepaid insurance. The increase in prepaid insurance iswas due to the increase in the size of our drilling rig fleet from 24 rigs at March 31, 2003 to 35 rigs at March 31, 2004.

        The increase in accrued payroll iswas due to the approximately 50% increase in our number of employees and the increase in the number of payroll days included in the accrual from seven at March 31, 2003 to nine at March 31, 2004.

        The total increase in accrued expenses at March 31, 2004 from March 31, 2003 was due to an increase of approximately $477,000 in the accrual for our insurance deductibles and additional insurance premiums, expense accruals of approximately $250,000 related to the sale of common stock in February and accrued property taxes of approximately $205,000 due to increases in rig valuations and the size of our rig fleet.

        Our working capital decreased to $2,251,383 at June 30, 2004 from $6,028,018 at March 31, 2004. Our current ratio, which we calculate by dividing our current assets by our current liabilities, was 1.08 at June 30, 2004 compared to 1.27 at March 31, 2004. The principal reason for the decrease in our working capital at June 30, 2004 was our use of approximately $2,600,000 of working capital to complete the construction of a drilling rig which we placed in service in late May 2004 and rig upgrades of approximately $1,200,000. Our operations generated cash flows in excess of our requirements for debt service and normal capital expenditures. If necessary, we can defer rig upgrades to improve our cash position. Therefore, we believe our cash generated by operations and our ability to borrow on our currently unused line of credit of $2,500,000 should allow us to meet our routine financial obligations.

The changes in the components of our working capital as of December 31, 2004 compared to March 31, 2004 were as follows:

        The increase in our receivables at June 30,December 31, 2004 from March 31, 2004 was due to our operating one14 additional rig andrigs, the improvement in rig utilization and revenue rates.rates and the timing of the completion of contracts as reflected in the decrease in contract drilling in progress. We invoiced approximately $18,500,000 of completed work in December 2004.

        The increasechange in contract drilling in progress was primarily due to the number and stage of completion of turnkey contracts in progress at June 30,December 31, 2004 compared to March 31, 2004.

        Substantially all our prepaid expenses at June 30,December 31, 2004 consisted of prepaid insurance. We renew and pay our insurance premium in late October of each year. At June 30,December 31, 2004, we had amortized eighttwo months of the premiums, compared to five months of amortization as of March 31, 2004.

        The increasedecrease in accounts payable was due to the increasedecrease in turnkey contracts completed during JuneDecember and in progress at June 30,December 31, 2004. We had seven turnkey and four footage contracts in progress at December 31, 2004, and rig upgrades.compared to 16 turnkey contracts in progress at March 31, 2004.

        The increase in accrued payroll was due to the 16increase in our number of employees due to the rig additions, partially offset by only four days of payroll accrual at June 30,December 31, 2004 versus 9compared to nine days at March 31, 2004.

        The increase in accrued expenses at June 30,December 31, 2004 fromcompared to March 31, 2004 was primarilyis principally due to increases of approximately $480,000the increase in our accrualsthe accrual for property taxes and self insurance deductibles and additional insurance premiums, approximately $475,000 for six months compared to three months ofcosts, partially offset by a decrease in accrued interest on subordinated debt and approximately $221,000 for six months compared to three months of accrued property taxes.expense.

Long-term Debt

        Our long-term debt at MarchDecember 31, 2004 and June 30, 2004 consisted of the following:of: